Net Income of $120 Million and Adjusted EBITDA of $119 Million for the Year; Announcement of Successful Completion of Series of Strategic Investment Transactions in April 2015

DENVER, CO--(Marketwired - April 16, 2015) - Venoco, Inc. ("Venoco", the "company", "we", or "us") today reported financial and operational results for the fourth quarter and full-year 2014. The company reported net income for the year of $120 million on total revenues of $224 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain one-time charges, were $19 million for the year, and Adjusted EBITDA was $119 million. Please see the end of this release for definitions of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net income/loss.

Highlights include the following:

Production of 2.7 million barrels of oil equivalent (MMBOE) for the year, or 7,406 BOE per day (BOE/d); excluding volumes contributed by the West Montalvo field properties which were sold in the fourth quarter of 2014, production for the year was 2.3 MMBOE or 6,233 BOE/d.

Successful drilling and completion of a well in the Monterey 2 (M2) zone at the Sockeye field from Platform Gail.

Continuation of our successful development program at the West Montalvo field, preceding the subsequent divestiture of the West Montalvo properties in order to support our deleveraging efforts.

Proved reserves of 40.4 MMBOE as of December 31, 2014, having PV-10 of $734 million. Please see the end of this release for a definition of PV-10 and a reconciliation of this measure to standardized measure of discounted future net cash flows.

Successful completion of a confirmation well in Coal Oil Point, an analogous but separate geologic structure in the South Ellwood field and located northeast of Platform Holly.

Completion and acceptance by the California State Lands Commission of our application to adjust the lease line of our South Ellwood field.

"2014 was a remarkable year with respect to contrast and volatility," said Mark DePuy, Venoco's CEO. "We began the year with oil prices over $100 per barrel and a plan in place to execute on a vigorous drilling program at three of our major fields. Out of the gate, however, we were faced with an unexpected and prolonged shutdown at South Ellwood due to a third-party pipeline repair, which delayed our drilling program considerably. We initially focused our drilling efforts at West Montalvo, continuing a successful development program that we had pursued over the past couple of years. We then shifted attention towards the effort to sell the field in support of our corporate deleveraging efforts. We received excellent value for the property and were able to consummate the deal before oil markets declined very significantly. We also continued drilling at Platform Holly towards Coal Oil Point, confirming our discovery in 2013 and ultimately completing one of the most technical and challenging wells drilled by the company to date. That was followed up later in the year by a successful drilling program at Platform Gail, where we drilled a successful Monterey well and proved up additional reserves."

"By the end of the year, our entire industry was grappling to adjust to the new commodity price paradigm, and we were no different," Mr. DePuy continued. "We quickly took the necessary steps to weather the latest downturn and to strengthen our company in anticipation of an eventual return to growth, as evidenced by the engagement of some of the industry's top financial and strategic advisors in the fourth quarter."

"Today, we turn our focus ahead, having successfully completed a major transaction that went a long way towards boosting liquidity and improving our balance sheet," Mr. DePuy added. "While we're pleased with the recent financing round, we'll continue to seek out further opportunities for capital structure improvements, acquisitions, and growth."

Fourth Quarter and Full-Year Production

Production in the fourth quarter of 2014 was 6,612 BOE/d compared to 7,344 BOE/d in the third quarter of 2014 and 8,511 BOE/d in the fourth quarter of 2013. Pro forma for the sale of the West Montalvo, production was 6,158 BOE/d in the fourth quarter of 2014, 6,013 BOE/d in the third quarter of 2014, and 7,027 BOE/d in the fourth quarter of 2013. Production for the full year 2014 was 7,406 BOE/d compared to 9,499 BOE/d in 2013. Pro forma for West Montalvo, production was 6,233 BOE/d in 2014 compared to 7,606 BOE/d in 2013, which is also pro forma for the sale of certain Sacramento Basin properties in 2013.

"Compared to the third quarter of 2014, our fourth quarter 2014 production was boosted by the successful drilling efforts at Platform Holly and Platform Grace, despite some continued downhole wellbore communication issues at Platform Holly," said Mr. DePuy. "However, production has remained relatively flat through the first part of 2015, and we believe the South Ellwood field decline as a result of the communication has moderated considerably."

The following table details the company's daily production by region (BOE(1)/d):

Full Year(2)

4Q 2013

3Q 2014

4Q 2014

2013

2014

Southern California (excl. W. Montalvo)

7,027

6,013

6,158

7,606

6,233

West Montalvo

1,484

1,331

454

1,614

1,173

Sacramento Basin

-

-

-

279

-

Total Venoco

8,511

7,344

6,612

9,499

7,406

(1)

Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

(2)

2013 production from the Sacramento Basin relates to properties that were held in escrow pending the receipt of consents regarding the transfer of ownership. As of May 1, 2013, title to all properties included in the sale on December 31, 2012 had been transferred.

Fourth Quarter and Full-Year Costs

Venoco's fourth quarter 2014 lease operating expenses were $27.07 per BOE compared to $26.96 per BOE in the third quarter. Pro forma for the West Montalvo sale, fourth quarter 2014 lease operating expenses were $28.07 per BOE compared to $27.10 in the third quarter. The increase in lease operating expenses per BOE was primarily due to higher non-recurring surface and subsurface costs at South Ellwood and Sockeye. Full-year 2014 lease operating expenses were $26.77 per BOE compared to $22.44 per BOE for the full-year 2013. Pro forma for the West Montalvo and Sacramento Basin field sales, full-year 2014 lease operating expenses were $27.75 per BOE compared to $23.89 per BOE for the full-year 2013. On an absolute basis, pro forma for the West Montalvo and Sacramento Basin field sales, full-year 2014 lease operating expenses were $63 million, down from $66 million for the full-year 2013.

Venoco's G&A costs were $922,000 in the fourth quarter of 2014, $1.4 million in the third quarter of 2014, $19.9 million for 2014 as a whole and $50.4 million in 2013. On a per BOE basis, Venoco's fourth quarter 2014 G&A costs, excluding non-cash share-based compensation, were $6.18 per BOE, down from $7.29 per BOE in the third quarter. Excluding production from the West Montalvo field, fourth quarter 2014 G&A costs, excluding non-cash share-based compensation, were $6.64 per BOE, down from $8.91 per BOE in the third quarter 2014. The company's full-year 2014 G&A costs, excluding the severance costs related to the sale of the West Montalvo field and non-cash share-based compensation, were $8.39 per BOE, down from $11.75 per BOE for the full-year 2013. Excluding production from the West Montalvo field, full-year 2014 G&A costs excluding non-cash share-based compensation were $9.97 per BOE, down from $14.67 per BOE for full-year 2013, which also excludes production from the Sacramento Basin properties held in escrow.

Property and production taxes for the full-year 2014 were $2.82 per BOE compared to $1.02 per BOE in 2013. Pro forma for the sale of West Montalvo, full-year 2014 property and production taxes were $2.94 per BOE compared to $0.91 per BOE for full-year 2013, which is also pro forma for the Sacramento Basin properties held in escrow. The increase is due primarily to higher supplemental and ad valorem taxes.

Quarter Ended

Year Ended

UNAUDITED (per BOE)

12/31/13

9/30/14

12/31/14

12/31/13

12/31/14

Lease Operating Expenses

$

29.46

$

26.96

$

27.07

$

22.44

$

26.77

Property and Production Taxes

1.86

3.14

2.44

1.02

2.82

DD&A Expense

15.72

17.39

15.35

14.09

16.31

G&A Expense (1)

14.31

7.29

6.18

11.75

8.39

(1)

Net of amounts capitalized and excluding non-cash share-based compensation costs, and severance costs associated with the sale of our West Montalvo and Sacramento Basin assets. See the end of this release for a reconciliation of G&A per BOE.

Capital Investment 2014

Venoco's 2014 capital expenditures for exploration, exploitation, development and other spending were $77 million, including $62 million for drilling and rework activities, $4 million for facilities, and the remaining $11 million for land, seismic and capitalized G&A.

In 2014, the company spent $73 million or 95% of its capital expenditures on its Southern California legacy fields. During the year, Venoco drilled one well at the Coal Oil Point structure in the South Ellwood field, which is located on the north east side of the field. The lowest zone of the well tested wet, but in August, we completed a higher zone of the well, which proved to be hydrocarbon bearing and was placed on initial production on August 20, 2014. As of December 31, 2014 this zone was producing approximately 440 Bbls/d.

In the Sockeye field, we performed one recompletion and drilled one development well in the M2 zone from Platform Gail. The well began producing on October 15, 2014 and initially produced approximately 610 Bbls/d.

In 2014, the company had onshore Monterey capital expenditures of $4 million or 5% of its total 2014 capital expenditures. Over the year, the company concentrated on the Sevier area, with capital expenditures primarily on recompletion work and on leasehold, facilities and capitalized G&A.

In the West Montalvo field, we drilled and completed two new well locations and concluded the drilling and completion of two wells that were spud in 2013 prior to selling the property in October, 2014.

"In light of the weakened commodities markets, we have significantly reduced our capital program in 2015 compared to prior years. We remain poised to initiate development drilling activities should economic or market conditions improve," Mr. DePuy added. "Our current capital expenditure budget for 2015 is about $18 million with the focus primarily on operational improvements, regulatory, health, safety and environmental compliance and advancing some of our significant future long-lead projects."

"We've also enacted comprehensive expense reduction programs across our assets," Mr. DePuy added. "Our increased focus on optimizing our operational efficiencies will also help us manage the macro environment and also preserve liquidity."

Reserves Review

The company's year-end 2014 total proved reserves were 40.4 million BOE, compared to year-end 2013 reserves of 53.1 million BOE.

The company's 2014 roll forward of proved reserves is as follows:

2014 Reserve Roll forward

MBOE(1)

Beginning of the year reserves

53,060

Revisions of previous estimates

(3,361

)

Extensions and discoveries

281

Purchases of reserves in place

-

Production

(2,703

)

Sales of reserves in place

(6,895

)

End of year reserves

40,382

Proved developed reserves:

Beginning of year

36,240

End of year

27,777

(1)

Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The company's 40.4 MMBOE of reserves, and the $734 million pre-tax PV-10 value of those reserves, is based on the year-end 2014 reserve report using SEC benchmark pricing of constant WTI Oil price of $94.99 per barrel and constant Henry Hub Gas price of $4.35 per MMBTU.

The following table details the company's reserve categories and PV-10 for the last three years:

Net Proved Reserves (end of period)

2012

2013

2014

Oil (MBbls)

Developed

35,115

34,508

26,287

Undeveloped

15,320

16,266

12,273

Total

50,435

50,774

38,560

Natural Gas (MMcf)

Developed

7,255

10,394

8,941

Undeveloped

3,595

3,322

1,992

Total

10,850

13,716

10,933

Total Proved Reserves (MBOE)(1)

52,243

53,060

40,382

PV-10 ($000)

Developed

$

1,076,145

$

1,008,760

$

495,231

Undeveloped

433,588

449,142

239,082

Total

$

1,509,733

$

1,457,902

$

734,313

(1)

Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

Investor Presentation

In order to provide an update to investors and other interested parties, a Venoco Corporate Presentation has been uploaded to the Events & Presentations page under the Investor Relations section of the company's website at http://www.venocoinc.com.

About the Company

Venoco is an independent energy company primarily engaged in the acquisition, exploitation and development of oil and natural gas properties primarily in California. Venoco operates three offshore platforms in the Santa Barbara Channel, has non-operated interests in three other platforms and operates onshore properties in Southern California.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, capital expenditures and development projects, and all other statements except statements of historical fact, are forward-looking statements. Forward-looking statements herein include those relating to future development and other opportunities, capital expenditure plans and future liquidity. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the company's future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher than expected production costs and other expenses, pipeline curtailments by third parties, and a potential inability to complete transactions as anticipated. The company's projects are subject to numerous operating, geological and other risks and may not be successful. All forward-looking statements are made only as of the date hereof and the company undertakes no obligation to update any such statement. Further information on risks and uncertainties that may affect the company's operations and financial performance, and the forward-looking statements made herein, is available in the company's filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein.

OIL AND NATURAL GAS PRODUCTION AND PRICES

Quarter Ended

Quarter Ended

Year Ended

UNAUDITED

9/30/14

12/31/14

% Change

12/31/13

12/31/14

% Change

12/31/13

12/31/14

% Change

Production Volume:

Oil (MBbls) (1)

642

578

-10

%

731

578

-21

%

3,180

2,555

-20

%

Natural Gas (MMcf)

202

181

-10

%

312

181

-42

%

1,724

883

-49

%

MBOE

676

608

-10

%

783

608

-22

%

3,467

2,702

-22

%

Daily Average Production Volume:

Oil (Bbls/d)

6,980

6,283

-10

%

7,946

6,283

-21

%

8,712

7,002

-20

%

Natural Gas (Mcf/d)

2,196

1,976

-10

%

3,391

1,976

-42

%

4,723

2,422

-49

%

BOE/d

7,346

6,612

-10

%

8,511

6,612

-22

%

9,499

7,406

-22

%

Oil Price per Barrel Produced (in dollars):

Realized price before hedging

$

87.84

$

61.37

-30

%

$

90.55

$

61.37

-32

%

$

95.79

$

85.68

-11

%

Realized hedging gain (loss)

(2.15

)

16.26

-856

%

(5.63

)

16.26

-389

%

(7.66

)

(0.01

)

-100

%

Net realized price

$

85.69

$

77.63

-9

%

$

84.92

$

77.63

-9

%

$

88.13

$

85.67

-3

%

Natural Gas Price per Mcf (in dollars):

Realized price before hedging

$

4.98

$

4.45

-11

%

$

4.48

$

4.45

-1

%

$

4.06

$

5.29

30

%

Realized hedging gain (loss)

0.11

0.52

373

%

-

0.52

0

%

-

0.13

0

%

Net realized price

$

5.09

$

4.97

-2

%

$

4.48

$

4.97

11

%

$

4.06

$

5.42

33

%

Expense per BOE (in dollars):

Lease operating expenses

$

26.96

$

27.07

0

%

$

29.46

$

27.07

-8

%

$

22.44

$

26.77

19

%

Production and property taxes

$

3.14

$

2.44

-22

%

$

1.86

$

2.44

31

%

$

1.02

$

2.82

176

%

Transportation expenses

$

0.08

$

0.07

-13

%

$

0.06

$

0.07

17

%

$

0.05

$

0.07

40

%

Depreciation, depletion and amortization

$

17.39

$

15.35

-12

%

$

15.72

$

15.35

-2

%

$

14.09

$

16.31

16

%

General and administrative (2)

$

2.00

$

1.52

-24

%

$

25.15

$

1.52

-94

%

$

14.54

$

7.37

-49

%

Interest expense

$

20.17

$

20.86

3

%

$

16.84

$

20.86

24

%

$

18.78

$

19.47

4

%

(1)

Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on pipeline inventories, and oil pipeline sales nominations.

In addition to net income (loss) determined in accordance with GAAP, we have provided in this release our Adjusted Earnings and Adjusted EBITDA for recent periods. Both Adjusted Earnings and Adjusted EBITDA are non-GAAP financial measures that we use as supplemental measures of our performance.

We define Adjusted Earnings as net income (loss) before the effects of the items listed in the table below. We calculate the tax effect of reconciling items by re-performing our period-end tax calculation excluding the reconciling items from earnings. The difference between this calculation and the tax expense/benefit recorded for the period results in the tax effect disclosed below. We believe that Adjusted Earnings facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties. Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to our ongoing operations.

We define Adjusted EBITDA as net income (loss) before the effects of the items listed in the table below. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.

We present Adjusted Earnings and Adjusted EBITDA because we consider them to be important supplemental measures of our performance. Neither Adjusted Earnings nor Adjusted EBITDA is a measurement of our financial performance under GAAP and neither should be considered as an alternative to net income (loss), operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted Earnings or Adjusted EBITDA amounts shown are comparable to similarly named measures disclosed by other companies.

Quarter Ended

Year Ended

UNAUDITED ($ in thousands)

12/31/12

9/30/13

12/31/13

12/31/12

12/31/13

Adjusted Earnings Reconciliation

Net Income

$

(3,138

)

$

(2,911

)

$

(19,768

)

$

(46,587

)

$

14,319

Plus:

Unrealized commodity (gains) losses

(14,480

)

8,893

9,908

87,514

(19,523

)

Going private related costs

5,240

-

-

9,997

-

Severance costs

1,496

-

-

1,496

-

Loss on extinguishment of debt

1,520

16,787

465

1,520

38,549

Tax effects

-

-

-

-

-

Adjusted Earnings

$

(9,362

)

$

22,769

$

(9,395

)

$

53,940

$

33,345

Quarter Ended

Year Ended

UNAUDITED ($ in thousands)

12/31/13

9/30/14

12/31/14

12/31/13

12/31/14

Adjusted Earnings Reconciliation

Net Income

$

(19,768

)

$

39,525

$

80,105

$

14,319

$

120,437

Plus:

Unrealized commodity (gains) losses

9,908

(32,895

)

(80,088

)

(19,523

)

(106,631

)

One-Time Severance Costs

-

-

(208

)

-

2,816

Loss on extinguishment of debt

465

-

2,347

38,549

2,347

Tax effects

-

-

-

-

-

Adjusted Earnings

$

(9,395

)

$

6,630

$

2,156

$

33,345

$

18,969

Quarter Ended

Year Ended

UNAUDITED ($ in thousands)

12/31/13

9/30/14

12/31/14

12/31/13

12/31/14

Adjusted EBITDA Reconciliation

Net income

$

(19,768

)

$

39,525

$

80,105

$

14,319

$

120,437

Interest expense

13,185

13,635

12,683

65,114

52,609

Income taxes

-

-

-

-

-

DD&A

12,311

11,759

9,335

48,840

44,064

Impairment

-

-

-

-

817

Accretion of asset retirement obligation

611

629

639

2,477

2,491

Amortization of deferred loan costs

818

887

685

3,705

3,268

Loss on extinguishment of debt

465

-

2,347

38,549

2,347

Share-based compensation

8,492

(4,801

)

(5,051

)

9,680

(8,942

)

Restructuring Costs

-

-

535

-

535

One-Time Severance Costs

-

-

(208

)

-

2,816

Amortization of derivative premiums

1,018

1,204

1,203

4,002

4,815

Unrealized commodity derivative (gains) losses

9,908

(32,895

)

(80,088

)

(19,523

)

(106,631

)

Adjusted EBITDA

$

27,040

$

29,943

$

22,185

$

167,163

$

118,626

We also provide per BOE G&A expenses excluding severance costs related to the asset sales and non-cash share-based compensation charges. We believe that these non-GAAP measures are useful in that the items excluded do not represent cash expenses directly related to our ongoing operations. These non-GAAP measures should not be viewed as an alternative to per BOE G&A expenses as determined in accordance with GAAP.

UNAUDITED ($ in thousands, except per BOE amounts)

Quarter Ended

Year Ended

12/31/13

9/30/14

12/31/14

12/31/13

12/31/14

G&A per BOE Reconciliation

G&A expense

$

19,695

$

1,352

$

922

$

50,403

$

19,926

Less:

Non-cash share-based compensation expense

(8,492

)

3,574

2,837

(9,680

)

5,761

One-Time Severance Costs

-

-

-

-

(3,024

)

G&A Expense Excluding Share-Based Comp and Severance Costs

11,203

4,926

3,759

40,723

22,663

MBOE

783

676

608

3,467

2,702

G&A Expense per BOE Excluding Share-Based Comp and Severance Costs

$

14.31

$

7.29

$

6.18

$

11.75

$

8.39

MBOE excluding production from Sold Assets

645

553

566

2,773

2,271

G&A Expense per BOE Excluding Non-Cash Share-Based Comp -Excluding Production from Sold Assets

$

17.37

$

8.91

$

6.64

$

14.69

$

9.98

PV-10

The present value of future net cash flows (PV-10 value) is a non-GAAP measure because it excludes income tax effects. Management believes that before-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company's unique tax position and strategies, can make after-tax amounts less comparable. We derive PV-10 value based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using the arithmetic twelve-month average of the first of the month prices without giving effect to hedging activities or future escalation, and costs as of the date of estimate without future escalation, excluding non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%.